1. Field of the Invention
The present invention relates to an inflatable packer system used in a drill stem or formation testing tool. The testing tool is used to evaluate the producing potential or productivity of an oil or gas bearing zone prior to completing a well.
As drilling of a borehole proceeds, there may be indications, such as those obtained from studying the core, which suggest the desirability of testing a certain formation or formations for producing potential.
For the test, a testing tool is attached to the drill string and lowered into the uncased well bore to a zone to be tested. A packer or packers is/are used to isolate the zone to be tested. If the zone is close to the bottom of the well, a single packer may be used. If the zone to be tested is a considerable distance off the bottom, or if there are multiple zones, the zone can be straddled by two packers.
It is advantageous to have a tool that can be set at any depth in the well so that all zones can be tested on the same trip into the well. Therefore, the packer system should be designed so that the packer or packers can be inflated and deflated repeatedly.
2. Description of the Prior Art
Various drill stem testers have been provided with inflatable packer elements for sealing off a zone in an uncased hole. Some systems for inflating the packer elements are listed as follows:
a. Drill pipe rotation actuates a piston pump which displaces fluid into the packing elements;
b. Drill pipe reciprocation actuates a piston pump which displaces fluid into the packing elements;
c. Drill pipe set-down movement moves a piston which displaces fluid into the packing elements;
d. Either drill pipe rotation or weight setdown opens a valve allowing compressed gas from a tank to move a piston to displace fluid into the packing elements; and
e. A differential piston, with its larger area against annulus pressure, displaces fluid into the packing elements when a valve is opened by weight setdown.
A tool for well bore testing widely used in the industry is disclosed in U.S. Pat. No. 3,439,740 granted to George E. Conover. The Conover tool is representative of class (a) packer inflation systems (see above) wherein drill pipe rotation actuates a piston pump which displaces fluid into the packing elements.
The Conover tool has a plurality of parts which cooperate together to perform four basic operations; packer inflation by drill string rotation; flow testing by applying weight set-down on the drill string; shut-in pressure testing by upward pull on the drill string; and packer deflation by the simultaneous application of downward and rotational forces on the drill string to actuate a clutch which allows a mandrel to move downwardly which, in turn, moves a sleeve valve downwardly, thereby allowing the packers to deflate. When the packers are reset, initial rotation of the pump causes hydraulic fluid to force the sleeve valve upwardly whereupon further pumping will inflate the packers again.
Packer inflation is achieved by rotating the drill string, thus activating a cam-actuated piston pump. A drag spring at the lower end of the tool engages the bore of the well to prevent the housing of the tool from rotating with the pump cam. Drilling fluid is pumped into the packers, thereby inflating them. Seals and check valves in the pump prevent packer deflation if the pump stops pumping before weight set-down.
While the packers are inflating, the zone being isolated is vented to the well annulus above the upper packer to allow pressure buildup in the zone, due to packer inflation, to be relieved.
Flow testing is accomplished by weight set-down on the drill string, which is transmitted to the tool. A piston moves downwardly, sealing off the packers and opening a passageway from the isolated zone to the drill string. This allows flow from the isolated zone to the surface.
A shut-in pressure test is done by applying an upward pull to the drill string, moving the piston upwardly and thus closing the path to the surface. The zone then is put in communication with the well annulus above upper packer through a check valve.
Packer deflation is accomplished by simultaneously applying a downward force and rotating to the drill string. This actuates a clutch which allows a mandrel to move downwardly, carrying a sleeve valve along with it. The sleeve valve allows connection of the packer interiors with the well bore, thereby allowing the packers to deflate.
When the tool is reset for another test and the drill stem rotated, initial pumping pumps the sleeve valve upwardly along the mandrel until it resumes its original position. Further pumping then inflates the packers again.
However, the Conover tool has various shortcomings, one of which is the lack of a straight line concentric flow path through the tool without deviations or restrictions. Therefore, there is no possibility of running special tools into the packer section after they are set.
Also, the tool is mechanically complex due to the functional cooperation required for flow and shut-in testing as well as inflation and deflation of the packers. The manner in which deflation of the packers is accomplished requires a complicated clutch and valving arrangement. It also requires a simultaneous application of weight and rotation to the drill string.
Additionally, there is no provision in the Conover tool for deflating the packers in case of a deflation system malfunction. Therefore, if the packers are set and cannot be deflated, the entire tool must remain in the well until removed by some means, not disclosed.
Further, the check and relief valves to prevent packer deflation on loss of pressure in the pump and over inflation of the packers respectively, are integral with the pump. This necessarily means that the valves are small and susceptible to early failure due to the abrasive qualities of the drilling fluid being used to inflate the packers.
In addition, the drag springs on the bow spring section of the Conover tool are pushed into and out of the well. This feature subjects the springs to buckling and breaking.
Other drag springs are shown in the prior art which are intended to be pulled, whether running in or out of a well. One example is represented by U.S. Pat. Nos. 4,042,022 and 4,077,470 to Wills, et al., and Dane, respectively. Both patents relate to drag spring assemblies wherein bow springs are fixed at either end to collars which are free to move longitudinally on a casing. Longitudinal movement of the collars is limited by a single stop collar fixed to the casing between the collars.
Another type of drag spring is set forth in U.S. Pat. No. 2,248,160 to Crawford. The centering unit of the patent uses bow springs, the top and bottom ends of which are retained by collars which are fixed against longitudinal movement. The collars are longitudinally slotted and the top and bottom ends of individual bow springs may move independently in their respective slots. The longitudinal movement of an individual bow spring end is limited. Whether the bow springs are pulled when running in or pulling out would depend on the hole diameter.
An additional type is shown in U.S. Pat. No. 3,200,884 to Solum, et al. There, the centralizer uses bow springs which are connected, at either end, to end collars. The end collars are, in turn, slidably attached to stop collars which are fixed to the casing. There is a limited amount of movement between a respective end collar and stop collar.